1. Field of the Invention
The present invention generally relates to improvements in the combustion of carbonaceous fuels, and, more particularly, to improvements in steam generating systems having firing boilers with reduced emissions of nitrogen oxides while minimizing production of other pollutants.
2. Description of the Prior Art
The combustion of fossil fuels leads to the formation of NO.sub.x, a pollutant that leads to smog and acid rain, especially in urban environments. There are two sources of NO.sub.x, one is primarily formed during the combustion of solid fossil fuels, namely coal. The fuel bound nitrogen whose concentration is generally in the range of 1%, by weight, in the coal is the primary source of NO.sub.x in coal combustion. Additionally, combustion with oxygen in excess of the amount required for stoichiometric combustion, which is required for all fossil fuels to minimize other pollutants, such as carbon monoxide, results in the formation of thermal NO.sub.x. The thermal NO.sub.x concentration rises substantially at temperatures above about 3000.degree. F.
Coal is the primary fuel for utility boilers, and to efficiently burn it, requires combustion at 3000.degree. F. or higher. Consequently, both fuel bound and thermal NO.sub.x form in high concentration, especially in large coal fired boilers used in electric utility power plants. Several technologies are used to control the emissions of NO.sub.x from fossil, and especially coal, fired boilers. Among these control technologies are: Staged combustion in which initial fuel rich-combustion near the fuel injection zone is followed by excess air combustion in the furnace region of the boiler. There are a number of different staged combustion processes and system designs, depending on the boiler design. Another NO.sub.x control process is catalytic reduction in which the relatively cold combustion effluent of several 100.degree. F. is passed over a catalyst coated bed in the presence of ammonia. This process is called selective catalytic reduction, SCR. Another process, generally called selective non-catalytic reduction (SNCR), involves the injection of various chemical compounds, primarily urea or ammonia, with or without various chemical additives, into the combustion gases in the boiler furnace at temperatures at which the NO.sub.x to N.sub.2 reaction is favored. The method of the present invention falls within the field of SNCR processes. While all these NO.sub.x control processes reduce NO.sub.x emissions to varying degrees, they all have certain technical and economic disadvantages. For example, staged combustion results in unburned carbon in the fly ash, which represents an energy loss and may make the fly ash unsuitable for recycling. Also in a certain staged combustion design, called low NO.sub.x burners, chemical compounds can form that corrode boiler metal tubes. SCR requires costly catalyst structures, and regular catalyst replacement. The present invention discloses a SNCR method, whose background art will be discussed in the next section. The present invention eliminates some of the technical and economic disadvantages in prior art NO.sub.x control methods, primarily in prior art of SNCR of NO.sub.x.
As discussed above, there is an extensive prior art on different NO.sub.x reduction methods in fossil fuel fired combustion systems. The prior art of direct relevance to the present invention is in the use of selective non-catalytic reduction (SNCR) of NO.sub.x.
An early disclosure of non-selective catalytic reduction is U.S. Pat. No. 3,900,554 to Lyon describing a method for reducing the concentration of NO in combustion effluents in the presence of oxygen using ammonia or a precursor thereof. Although the Lyon patent indicates that the ammonia is contacted with the effluent at a temperature where they mix of 1600 to 2000.degree. F., the patent fails to reveal how the procedure might be performed inside the combustion zone of a boiler. In U.S. Pat. Nos. 4,208,386 and 4,325,924, Arand discloses the injection of urea into the combustion zone of a fossil fuel fired boiler. The preferred injection temperature is stated as 1900.degree. F., with an allowable range of 1600.degree. F. to 2000.degree. F. Above 2000.degree. F. additional NO.sub.x is formed. The use of a reducing agent, such as hydrogen is stated as allowing the SNCR reaction to proceed at temperatures as low as 1300.degree. F. In the burner zone of a boiler the temperature is generally in the range of 3000.degree. F. Therefore, the urea injection must take place far away from this zone, presumably at the end of the radiative section of the boiler. Since a large utility boiler can operate over a wide fuel input range as customer electric power requirements change during the day, the temperature at the preferred point of injection can change. Therefore, Arand discloses the use of additives or injection of reducing gases, such as hydrogen, with the urea to allow the SNCR process to proceed with NO.sub.x to N.sub.2 conversion if the temperature at the point of urea injection changes with boiler load variation. However, as in Lyon, the Arand patents fail to reveal how the procedure might be performed inside the combustion zone of a boiler. Arand does not teach actual means of injection of the urea-water solution insofar as to droplet sizes or injection means. The allowable residence times taught by Arand of from 0.001 to 10 seconds is dubious, namely, the lower range is much too short, while the latter range is much too long for residence times in the proper temperature range of an industrial or utility boilers ranging from 10,000 lb/hr of steam production to over 100 MW power production.
Despite such objectives in the prior art, there remains a great need for possible techniques and related wherewithal for actually implementing an effective injection of reducing agents, while in an appropriate physical state for the reduction reaction, into contact with combustion effluents at the critical temperature range in the combustion zone of a boiler. Injection of urea or ammonia outside the temperature range at which it is effective in converting (reducing) NO.sub.x to N.sub.2, or inadequate mixing of the urea or ammonia in the proper temperature zone, results in excess ammonia being conveyed to cooler portions of the combustion gas effluent gas stream. In coal fired boilers, this excess ammonia can combine with the sulfur in the gas stream to form ammonium sulfate or ammonium bisulfate. The former may contribute to stack plume formation, while the latter can foul air heater surfaces. (Steam, Its Generation & Use, 40th Edition, Chapter 40, Babcock & Wilcox Company, New York, N.Y., 1992) Also the ammonia may attach to fly ash, rendering it unfit for beneficial use. To prevent these results, the free ammonia in the gas downstream of the injection zone must be limited to less than 10 parts per million by volume (ppmv), and preferably less than 5 ppmv.
Other prior patents, for example, Pat. Nos. 4,719,092 and 4,751,065 to Bowers are representative of inventions that disclose use of various chemical additives to extend the temperature range of the urea/ammonia reaction with NO.sub.x to a wider temperature range than urea or ammonia by itself. These patents also fail to provide concrete teachings of how an implementation might be carried out to inject the urea into the effluent in a proper physical state and temperature in order to obtain high NO.sub.x reduction with acceptably low ammonia in the effluent.
U.S. Pat. No. 5,252,298 to Jones teaches the use of an air or steam flow to atomize the aqueous urea solution inside an injection chamber, said chamber having an air flow that is used to entrain the atomized droplets and inject them into the boiler. These injectors are placed at multiple locations in the boiler wall and the resulting air jet is of such velocity that, according to Jones' use of gas dynamic theory of jets, the jet will reach the opposing wall of the boiler without substantial deflection from the combustion gas flow in the boiler. Jones admits that a significant percentage of atomized droplets will impact the wall inside the injection chamber. Thus the benefit of atomization is lost for this wall impacted liquid. Jones recognizes this and incorporated a "scrubber" to re-entrain this wall material, but he does not teach how this is accomplished or how effective it is. Furthermore, Jones stated purpose of having the jets emerging from his injectors into the boiler furnace is to achieve substantial mixing of these jets with the combustion gases in the furnace. However, if as he teaches, the jets travel to the far wall without significant deflection from the combustion gas stream, then mixing can be expected to be very limited.
Hunt U.S. Pat. No. 5,165,903 also teaches the use of multiple air atomized aqueous solutions of urea or ammonia to reduce NO.sub.x in a 100 MW coal fired boilers. This process is combined with initial NO.sub.x reduction with staged combustion using a low NO.sub.x coal burner with subsequent air injection into the furnace to reduce the NO.sub.x. To further reduce NO.sub.x, aqueous urea is injected into the gas stream in the boiler with multiple air atomized nozzles at a location where the gas temperature was 1420.degree. F. to 1820.degree. F. The nozzle design is not disclosed. The ammonia remaining from the urea injection is several times greater than the maximum allowable to limit the negative effect of ammonia at a low temperature, upstream of the stack gas baghouse. It is subsequently reduced to acceptable levels at the stack outlet, by a mechanism not disclosed, although a chemically active sodium reagent is injected upstream of the baghouse.
In subsequent tests by Hunt in the same 100 MW coal fired boiler, the ammonia remaining in the flue gas exhaust was too high to limit the deleterious effect of ammonia on the air heater and stack plume. As a result, the urea was first converted externally to the boiler into ammonia which was then injected in aqueous form into the boiler. ("Integrated Dry NO.sub.x /SO.sub.2 Emission Control System", T. Hunt and J. Doyle, Proceedings Second Annual Clean Coal Technology Conference, Page 821, U.S. Department of Energy, Atlanta, Ga., Oct. 18-22, 1992). This of course increases the cost of the process.
The difficulty of injecting a sorbent, such as urea, into a large boiler and achieving high NO.sub.x reduction without unacceptably high ammonia effluent at the stack is also illustrated by Hofmann ("NO.sub.x Control in a Brown Coal Utility Boiler", J. E. Hofmann et al., in Proceedings: 1989 Joint Symposium on Stationary Combustion NO.sub.x Control, Vol. 2, U.S. EPA, EPA-600/9-89-062b {NTIS PB89-220537}, 7A-pp. 53-66, (June 1989)). Aqueous urea was mixed with a proprietary additive and injected into a 150 MW boiler through 12 injector nozzles at one elevation in the boiler. Only 30% to 50% NO.sub.x reduction was achieved before the ammonia effluent reached the upper acceptable effluent limit of 10 ppm in the stack. The lower NO.sub.x figure applies with 10% addition of the proprietary enhancer, while the higher figure applies with 20% addition. A gas temperature profile over the boiler gas path cross-section at the elevation of the 12 injectors shows a cool outer ring from the boiler tube wall to a distance of about 8 to 12% of the square boiler width where the gas temperature was below 900 .degree. C. (1650.degree. F.). The gas temperature increases in a series of concentric rings to 1050.degree. C. (1921.degree. F.) at the center of the boiler. Since utility boilers have peak water/steam temperatures of about 1000.degree. F., the boiler wall temperature even with ash deposits on it will probably be at most a few 100.degree. F. above the water/steam temperature. Therefore a zone of at least several feet will exist where the urea laden droplets can vaporize but where the temperature is below the optimum for urea reaction with NO.sub.x. With the enhancers, this zone may be reduced somewhat. However, any urea vaporized in this boundary layer will be rich in ammonia which will preferentially flow out to the stack. The impact of this zone on the urea-NO.sub.x reduction process is not discussed by Hofmann. However, Jones in U.S. Pat. No. 5,252,298 states that at high temperature the non-catalytic reaction of urea or ammonia with NO.sub.x is very fast and that air atomized droplets cannot penetrate very far into a large combustion chamber.
The above citation illustrates the important role of proper injection of the aqueous urea or ammonia solutions into the hot combustion gas stream, and the various approaches and difficulties in achieving NO.sub.x reduction with acceptable ammonia effluent. Therefore, the statement by Epperly in U.S. Pat. No. 4,780,289 that the injection method of aqueous droplets for the SNCR application is "familiar to those skilled in the art" is clearly open to question.
In an attempt to solve the problem of ammonia in the effluent from the SNCR process, a number of prior inventors have proposed a two step process, namely SNCR followed by SCR. In the latter process, the ammonia is consumed in the catalytic reaction in which additional NO.sub.x is removed. Examples of dual NO.sub.x reduction disclosures are: U.S. Pat. Nos. 4,780,289 and 4,777,025 both to Epperly, and U.S. Pat. No. 5,465,690. While this achieves over 90% NO.sub.x reduction, it adds substantially to the cost of NO.sub.x removal. According to Jones in U.S. Pat. No. 5,240,689, it involves a capital investment of between $60 to $120/kW plus replacement of the catalyst every 1 to 2 years. Additionally, the excess ammonia reacts with the SO.sub.2 from coal combustion to form ammonium bisulfate at 500.degree. F. which fouls the boiler's air heaters. This temperature is higher than the temperature at which the SCR process operates, which is downstream of the air heater. These are issues not addressed in the above cited dual NO.sub.x reduction inventions.
In the invention by Hunt, U.S. Pat. No. 5,165,903, staged combustion was disclosed using "low NO.sub.x " burners in pulverized coal, dry ash utility boilers to initially reduce the NO.sub.x before applying the SNCR process. The "low NO.sub.x burner" option is not available in utility boilers that use slagging coal combustors in which crushed coal is burned (Steam, Its Generation & Use, 37th Edition, Chapter 28, Babcock & Wilcox Company, New York, N.Y., 1960). These combustors must operate at excess air condition to burn the large coal particles, and as a result they emit high levels of NO.sub.x, in excess of 1 lb/MMBtu.
U.S. Pat. No. 4,756,890 to Tang et al. describe reduction of NO.sub.x in a flue gas by mixing the reducing agent with the flue gas stream in a high-temperature cyclone separator located at the outlet of a boiler, such as a fluid bed boiler. The reason Tang et al. state for inserting injectors in the vortex region of a cyclone separator, and not in boilers per se, is in order for the NO.sub.x reduction reaction to take place at a location where there are no CaO particles carried over from the fluid of the fluid bed boilers. The specific construction of the injectors that might be useful to provide the described droplet sizes inside the cyclone, however, are not revealed by Tang et al.
U.S. Pat. No. 4,624,191 to Zauderer discloses a slagging cyclone combustor that utilizes finely crushed or pulverized coal that burns primarily in suspension in the combustor and can operate under fuel rich conditions needed for staged combustion and NO.sub.x control. At stoichiometric ratios of 70% to 80% in a 20 MMBtu/hr air cooled, slagging combustor designed according to this invention, with final combustion of the exhaust gas in the boiler, ("An Air Cooled Slagging Combustor with Internal Sulfur, Nitrogen, and Ash Control for Coal and High Ash Fuels", B. Zauderer, E. S. Fleming and B. Borck, Proceedings First Annual Clean Coal Conference, Page 6-3, U.S. DOE, Cleveland, Ohio, Sep. 22-24, 1992, Conf 920979) NO.sub.x emission were reduced well in excess of 50% compared to operation under excess air conditions. However, at these fuel rich conditions, unburned carbon over 10% of the total carbon in the coal was carried out of the combustor as fine particles entrained in the exhaust gas. Reducing the degree of fuel rich operation in the combustor greatly reduced the unburned carbon at the expense of increased NO.sub.x emissions. Therefore, this combustor is a candidate for dual NO.sub.x emission control in combination with SNCR.
As can be appreciated from the above, the achievement of extremely high NO.sub.x reduction, namely in excess of 90%, requires the use of the costly SCR process. Staged combustion results in unburned carbon carried out of the combustion zone at high levels of NO.sub.x reduction, and it is not suitable for crushed coal, cyclone combustor fired boilers. SNCR of NO.sub.x emission processes individually cannot achieve very high NO.sub.x reductions without the undesirable effect of increased ammonia effluents in exhaust stack gas, increased carbon monoxide emission when urea is used, and increased cost when combined with SCR processes. In addition, considerable difficulties and uncertainties are found in connection with the injection of aqueous solutions of urea or ammonia. The present invention discloses an effective approach to overcoming these difficulties and drawbacks associated with conventional SNCR processing.